A major goal in the evaluation of hydrocarbon bearing Earth formations is the accurate determination of the volumes of oil and water in the pore space of sedimentary rocks. Measurements made with signals from logging instruments have been used to obtain estimates of these volumes. The most credible measurement of producibility of the fluid volumes is to actually produce fluids from the formation; such as by using a drill stem test or by using a logging device that extracts fluids from the formations.
However, it is desirable to determine the nature of the earth formation and make estimates of the bulk volume of the fluids present in the formation, as well as their producibility, prior to undertaking the measures set forth above. Petrophysical parameters of a geological formation which are typically used to determine whether the formation will produce viable amount of hydrocarbons include the formation porosity, fluid saturation, the volume of the formation and its permeability. Formation porosity is the Dore volume per unit volume of formation; it is the fraction of the total volume of a sample that is occupied by pores or voids. The saturation of a formation is the fraction of its Dore volume occupied by the fluid of interest. Thus, water saturation is the fraction of the Dore volume that contains water. The water saturation of the formation can vary from 100 percent to a small value that cannot be displaced by oil, and is referred to as irreducible water saturation. For practical purposes it is assumed that oil or hydrocarbon saturation of the formation is equal to one minus the water saturation. Obviously, if the formation's pore space is completely filled with water, such a formation will not produce oil or gas and is of no interest. Conversely, if the formation is at an irreducible water saturation, it will produce all hydrocarbons and no water. Finally, the permeability of a formation is a measure of the ease with which fluids can flow through the formation, i.e., it's producibility.
Traditional methods of determining these parameters called for the use of wireline logging or logging while drilling (LWD) techniques which generally include resistivity, gamma, and neutron-density measurements, commonly known as the “triple-combo.” In the instance of a wireline measurement, the tool is typically lowered below the zone of interest on an armored multiconductor cable, providing for power and communications, and moved upwardly through the borehole while making the measurements. In the instance of LWD logging, the measurements are made while drilling is taking place, the tools being mounted on specialized subs in the drilling string. Each of these methods has their advantages. The wireline method is generally capable of providing a more accurate measurement as well as more real time data. The LWD method, while being more susceptible to environmental effects, such as tool position within the borehole, makes the measurements in a relatively new borehole, generally prior to any invasion by components of the drilling fluids into the formation. The triple combo measurements are subject to a number of borehole environmental effects. Resistivity tools respond to conductive fluids, including moveable water, clay bound water, capillary bound water and irreducible water. While a number of models have been developed to estimate the water saturation of the formation, the recognition of pay zones within an earth formation is difficult because no conductivity contrast exists between capillary-bound water and moveable water. Further, the resistivity measurement is subject to borehole rugosity and mudcake effects. Similarly, the methods utilized to determine porosity were lacking in detail in that neutron-density measurements responded to all components within the formation but are more sensitive to the formation matrix as opposed to the fluids contained therein. Even after cross plot corrections, borehole rugosity, mudcake, lithology and other environmental effects can adversely effect this measurement.
Nuclear magnetic resonance (NMR) logging is relatively recent commercial method developed to determine the above formation parameters, as well as other parameters of interest, for a geological formation and clearly has the potential to become the measurement of choice for characterizing formation fluids. This is due, at least in part, to the fact that unlike nuclear porosity logs, which utilize isotopic radioactive sources, the NMR measurement is environmentally safe and is less affected by variations in matrix lithology than most other logging tools. The NMR logging method is based on the observation that when an assembly of magnetic moments, each of which having a certain angular momentum, are exposed to a static magnetic field they tend to align at a certain angle to the direction of the magnetic field, and will precess with the Larmor frequency around the direction of the magnetic field. The rate at which equilibrium is established upon provision of a static magnetic field is characterized by the parameter T1, known as the spin-lattice relaxation time. Another related and frequently used NMR parameter is the spin-spin relaxation time constant T2 (also known as transverse relaxation time) which is an expression of the relaxation due to dynamic non-homogeneities on molecular length scales. Another measurement parameter used in NMR well logging is the self-diffusion coefficient of formation fluids, D. Generally, self-diffusion refers to the random motion of atoms in a gaseous or liquid state due to their thermal energy. Since the molecular propagation of pore fluid molecules is affected by pore geometry, the diffusion parameter D offers much promise as a separate permeability indicator. Diffusion causes atoms to move from their original positions to new ones. In a uniform magnetic field, diffusion has no effect on the decay rate of the measure to NMR echoes. In a gradient magnetic field, however, atoms that have diffused will acquire different phase shifts compared to atoms that do not move, and diffusion will thus contribute to a faster rate of relaxation.
Recent advances in the NMR logging tool design and interpretation have permitted users to obtain detailed information regarding formation characteristics porosity, fluid characterization and estimates of permeability. In particular, the MRIL® tool manufactured and utilized by the NUMAR product service line of Halliburton Energy Services and the CMR™ tool manufactured and utilized by Schlumberger Oilfield Services represent significant improvements in the field of NMR logging and are both capable of making porosity, permeability and fluid characterization measurements. Both tools utilize permanent magnets to provide a static magnetic B field and RF pulses to create a B1 fields as part of Carr-Purcell-Meiboom-Gill (CPMG) experiment. Using T1 and/or T2 echo information, one can determine a number of formation properties. Fluid saturation (porosity) is generally determined by means of signal intensity. Fluid typing utilizes T1, T2 and/or diffusion measurements and is usually based on the viscosity of the fluid being measured. The bulk volume index (BVI) and free fluid index (FFI) are measured based on T2 and empirically derived formulas. The formation permeability is also based on T1 and/or T2 measurements and one of several empirically derived models.
With respect to permeability, several models have been used to estimate formation permeability. The first method is based on T1 and/or T2 porosity and is estimated by various oilfield service and oil exploration companies according to equations 1-3 below:k˜φ4T12  [1]k=Cφ4T2ML2  [2]k˜φ2T12  [3]Where k is permeability, φ is porosity, C is an empirically derived constant and T2ML is the logarithmic mean of the T2 distribution.
Yet another model estimates formation permeability based on the bound water information (often referred to as the Coates model) according to equation 4 below:                     k        ∼                              [                                                            (                                      ϕ                    C                                    )                                2                            ⁢                              (                                  FFI                  BVI                                )                                      ]                    2                                    [        4        ]            where FFI is the free fluid index, which is determined by partitioning the total measured NMR response by the T2cutoff, which is the value of T2 that is empirically related to the capillary properties of the wetting fluid for the specific formation lithology. The porosity estimate below T2cutoff is generally referred to as the bound fluid porosity or bulk volume irreducible (BVI). While estimates of T2cutoff values have been made for various types of mineralogy, the only accurate means of determining T2cutoff is by performing NMR measurements on a core sample.
Another model for estimating formation permeability is based on the restricted diffusion and pore size of the formation as set forth in equation 5 below:k˜φ3/((1−φ)2τ(S/V)2)  [5]where S/V is the pore surface to volume ratio and τ is the rock tortuosity.
Each of the above models has drawbacks in their application. For instance, equation 4 (the Coates model) might not be valid if gas is present in the sample or if the estimate of the T2cutoff is significantly in error. The Carman-Kozeny model set forth in equation 5 was derived for an artificial lithology (glass beads) and has yet to be verified over wide range of reservoir lithology.
Other techniques have been used to estimate formation permeability. Primary among them is the use of formation test tools to determine formation permeability. A formation test tool is generally lowered into the borehole and brought into contact with the formation wall. A probe is inserted past the mud cake to come in contact with the formation itself. Fluid is then withdrawn from the formation using a pre-charge piston or pumping means. This “draw down” period induces fluid into the tool that may be diverted to sampling chambers or, ultimately, discharged back into the borehole. Following the draw down, formation pressure (and generally temperature) is measured as it builds back up to its natural formation pressure. There are a number of models for estimating permeability based on the formation pressure and temperature tool data. These models may include a laminar or spherical model design. The use of formation testers to determine permeability is well known and U.S. Pat. Nos. 6,047,239, 5,2447,830 and 4,745,802 set forth exemplary formation test tools. As noted previously, these formation test evaluation techniques pre-suppose the use of a particular model, which in turn pre-supposes the nature of the formation itself. The formation may be thinly laminated near the test point or have a large, consistent lithology. It will be appreciated that models designed to work in a consistent lithology will not yield as accurate a result where the formation is thinly laminated with the layers each having differing porosity and permeability characteristics. Formation test tools are generally incapable of measuring anisotropic permeability, i.e., vertical versus horizontal permeability. An additional downside to using formation test tools is the fact that logging tool movement must be stopped to permit the formation test tool to come into contact with formation, perform the draw down and permit the pressure to build back up. It may require several minutes to hours to perform the draw down and build up. It will be further appreciated prior to wireline logging operations, the drill string must be “tripped” or removed from the borehole to permit logging. This results in an associated cost over and beyond the cost of services associated with logging. The triple-combo and NMR logging tools noted above are used in continuous logging operations, that is, the measurements are made as the tool is moved up or down the borehole at rates exceeding three feet per minute. Indeed, modern borehole logging speeds generally exceed 30 feet per minute. Thus, while providing some information regarding permeability, formation test tools are costly to use when compared to NMR logging tools. At the same time, NMR logging tools make certain assumptions regarding permeability that may not be accurate in light of actual formation conditions.
Recently, some efforts have been made to combine NMR techniques with formation test tools. Halliburton, Schlumberger and Baker Atlas have introduced techniques in which fluid identification is performed on the fluid withdrawn from the formation during one of the formation tests. Examples on these types of techniques are set forth in U.S. Pat. Nos. 6,111,408 and 6,111,409. In each instance, the NMR experiment is performed on the fluid that is no longer in situ. As a result, it may undergo a phase change.
Other methods of formation characterization include in the use of imaging tools. These tools attempt to create an image of the borehole wall as it surrounds the tool. There are a number of different techniques utilized in this area. Primary among them are the use of acoustic or sonic information and microresistivity. Borehole acoustic imaging tools typically utilize an ultrasonic transducer to emit high frequency sonic energy that is reflected back from the borehole. The reflected signal is received by the transceiver and processed to create an image. The microresistivity technique places small electrodes against the side of the borehole wall and current is forced into the formation. Based on the return resistivity information, an image of the borehole wall can likewise be created. Both of these techniques have their drawbacks in that both require a great amount of time to hold the tools stationary in the borehole in order to make measurements. In the case of the electrical technique, the electrodes must be in contact with the borehole wall. Further, commonly used oil-based drilling muds have an adverse effect on the use of the microresistivity method. It will be appreciated that both of these techniques significantly increase the amount of time required for logging operations. Moreover, they provide only a portion of the information that may be sought in order to characterize the reservoir.
Further, there exists a continued need for accurately determining formation permeability at present, formation permeability can be derived in a number of different ways. One method utilizes a formation test tool wherein a small section of the borehole wall is isolated from the borehole. A fluid channel between the formation and the tool is created and fluid is drawn into the tool over a period of time. Pressure, temperature and fluid volumes are recorded and permeability is empirically derived using various models. Permeability may also be empirically derived utilizing NMR tools based on fluid volumes and various models.
Thus, there exits a need for a means for directly determining formation permeability, as well as providing an image of the formation where the measurement is made. Further, there exists a need for a means for determining anisotropic permeability where vertical permeability (kV) differs from horizontal permeability (kH).